1. Field of the Invention
This invention is concerned with monitoring the long-term changes in the distribution of the fluid content of a reservoir formed in a permeable subsurface rock formation. Changes in the fluid distribution give rise to concomitant changes is the acoustic signature of the reflected seismic signals that illuminated the reservoir rocks. Meaningful quantitative results require use of calibrated instrumentation.
2. Discussion of Related Art
As is well known to geophysicists a sound source, at or near the surface of the earth, is caused periodically to inject an acoustic wavefield into the earth at each of a plurality of regularly-spaced survey stations. The wavefield radiates in all directions to insonify the subsurface earth formations whence it is reflected back to be received by seismic sensors located at designated stations at or near the surface of the earth. The seismic sensors convert the mechanical earth motions, due to the reflected wavefield, to electrical signals. The resulting electrical signals are transmitted over a signal-transmission link of any desired type, to instrumentation, usually digital, where the seismic data signals are archivally stored for later processing. The travel-time lapse between the emission of a wavefield by a source and its reception by a receiver after reflection, is a measure of the depths of the respective reflecting earth formations.
The seismic survey stations are preferably distributed in a regular grid over an area of interest with inter-station spacings on the order of 25 meters. The processed seismic data associated with a single receiver are customarily presented as a one-dimensional time scale recording displaying rock layer reflection amplitudes as a function of two-way wavefield travel time. A plurality of seismic traces from a plurality of receivers sequentially distributed along a line of survey may be formatted side-by-side to form an analog of a cross section of the earth (two-dimensional tomography). Seismic sections from a plurality of intersecting lines of survey distributed over an area of interest would provide three-dimensional tomography.
The term "signature" used herein means the variations in amplitude and phase of an acoustic wavelet (for example, a Ricker wavelet) expressed in the time domain as displayed on a time scale recording. The impulse response means the response of the instrumentation to a spike-like Dirac function.
Wavefield reflection from a subsurface interface depends on the acoustic characteristics of the rock layers that define that interface such as density and wavefield propagation velocity. In turn those characteristics depend inter alia on the rock type, rock permeability and porosity, fluid content and fluid composition. In a subsurface reservoir, the fluid phase change from gas to oil or water may act as a weak reflecting surface to generate the so-called bright spots sometimes seen on seismic cross sections. It is reasonable to expect that a change in the level or the characteristics of the reservoir fluids will create a change in the seismic signature associated with the reservoir. Thus, time-lapse or 4-D tomography, that is, the act of monitoring the regional seismic signature of a reservoir over a long period of time would assist in tracking the depletion of the reservoir or the advance of thermal front in a steam-flooding operation.
The dimension of time as discussed in this disclosure may be expressed in two very different orders of magnitude. Wavefield travel times and discrete data-sample times are dimensionally resolved to seconds and thousandths thereof. In the realm of time-lapse tomography, the petrophysicist is concerned with changes in the seismic signature changes as seen on data sets that are separated in time by many months or years. To avoid ambiguity, the time lapse between long-term reservoir monitoring studies will be referred to as an epoch as opposed to the short-term (data) sample intervals or (wavefield) travel times.
Successful time-lapse monitoring requires that differences among the processed 3-D data sets must be attributable solely to physical changes in the petrophysical characteristics of the reservoir. That criterion is severe because changes in the data-acquisition equipment and changes in the processing algorithms, inevitable over many years, introduce differences among the separate surveys. Long-term environmental changes in field conditions such as weather and culture affect the outcome. If time-lapse tomography is to be useful for quantitative reservoir monitoring, instrumental and environmental influences that are not due to changes in reservoir characteristics must be transparent to the before-and-after seismic data sets. Successful time-lapse tomography requires careful preliminary planning.
One worker in the art studying reservoir steam flooding, found that certain reflections originating from strata above the reservoir were very repeatable over time. Therefore, it was reasoned, any changes in the signature of the reservoir rocks, absent concomitant changes in shallow reflecting horizons, were indeed indicative of physical changes in reservoir-rock parameters. In effect that technique is a type of self-calibrating method. That method is useful only in a geological domain where a reliable, homogeneous shallow reflecting horizon happens to be available.
U.S. Pat. No. 4,969,130 issued Nov. 6, 1990 to Cameron D. Wason et al. teaches a SYSTEM FOR MONITORING CHANGES IN FLUID CONTENT OF A PETROLEUM RESERVOIR. This is a system of monitoring the fluid contents of a petroleum reservoir, wherein a synthetic reservoir model is employed to predict the fluid flow in the reservoir. Included, is a check on the reservoir model by comparison of synthetic seismograms with the observed seismic data. If the synthetic output predicted by the model agrees with the observed seismic data, then it is assumed that the reservoir is being properly worked. If not, then the reservoir model, in particular the reservoir description, is updated until it predicts the observed seismic response. The seismic survey may be periodically repeated during the productive life of the reservoir and the technique used to update the reservoir model so as to ensure that the revised reservoir description predicts the observed changes to the seismic data and hence reflects the current status of fluid saturations.
The difficulty with the Wason reference is the need to generate a synthetic model of the reservoir after some period of elapsed time. The ultimate desideratum of time-lapse reservoir monitoring is to construct a reservoir model based upon hard data from seismic measurements after the reservoir characteristics have undergone imperfectly-known physical changes. Because those changes are imperfectly known, it is difficult to guess what the reservoir characteristics might look like a year or so later in order to create a hypothetical synthetic model for comparison purposes.
U.S. Pat. No. 5,461,594 issued Oct. 24, 1995 to Denis Mougenot et al. for a METHOD OF ACQUIRING AND PROCESSING SEISMIC DATA RECORDED ON RECEIVERS DISPOSED VERTICALLY IN THE EARTH TO MONITOR THE DISPLACEMENT OF FLUIDS IN A RESERVOIR, according to the Abstract, teaches a method of acquiring and processing seismic data for the repetitive monitoring of displacement of fluids impregnating a reservoir deep in the subsurface below the surface weathering zone comprises the steps of making at each point on a predetermined grid on the surface a vertical axis shallow borehole in the earth above the reservoir passing through the weathered layer, positioning in each borehole along its vertical axis a plurality of fixed receivers adapted to be connected separately to the seismic recorder on the surface, emitting near each borehole seismic waves into the earth by means of an emitter on the surface or close by the surface near the vertical axis of the borehole, recording for each borehole by means of receivers placed in the borehole to direct incident seismic waves and the seismic waves reflected at the interfaces of the deep strata of the subsurface, each receiver providing a separate record of an incident wave and a plurality of reflected waves, and carrying out the following process steps for each borehole: picking the first break of direct incident waves, horizontalizing the reflected waves, separating the reflected waves and the direct incident waves, deconvolving receiver by receiver the reflected waves by the direct incident wave in order to obtain a zero-phase trace for each receiver and stacking the zero-phase traces from the receivers to obtain a low coverage/zero-offset, zero-phase trace. This patent was concerned with a land system but its teachings could be extended to a marine system by installing the sensors in boreholes or crypts on the sea floor.
The inventors of the '594 patent recognize the need for maintaining identical instrumentation and processing methods throughout the reservoir-monitoring epoch. Therefore, sensors are permanently sealed in a plurality of boreholes distributed over the area of interest. A standard source and standard processing methods are used to maintain constant data-gathering/interpretation conditions throughout the monitoring epoch. The method avoids the guess-work of the '130 reference. But to monitor properly a reservoir of large areal extent, many hundreds or thousands of densely-distributed borehole-emplaced sensors would be needed, a very uneconomical installation indeed, which renders that method to not be very practical.
There is a need for a compact, minimally-equipped, permanently-installed, localized seismic calibration system that provides standardized seismic measurements throughout extended reservoir-monitoring epochs. Data output from the standard system is used for calibrating the seismic outputs of a conventional areally-distributed seismic system of whatever type that happens to be currently in favor at the time a detailed monitoring survey is undertaken during the epoch.